Petroleum refiners often produce desirable products such as turbine fuel, diesel fuel, middle distillates, naphtha, and gasoline boiling hydrocarbons among others by hydroprocessing a hydrocarbon feed stock derived from crude oil or heavy fractions thereof. Hydroprocessing can include, for example, hydrocracking, hydrotreating, hydrodesulfurization and the like. Feed stocks subjected to hydroprocessing can be vacuum gas oils, heavy gas oils, and other hydrocarbon streams recovered from crude oil by distillation. For example, a typical heavy gas oil comprises a substantial portion of hydrocarbon components boiling above about 371° C. (700° F.) and usually at least about 50 percent by weight boiling above 371° C. (700° F.), and a typical vacuum gas oil normally has a boiling point range between about 315° C. (600° F.) and about 565° C. (1050° F.).
Hydroprocessing is a process that uses a hydrogen-containing gas with suitable catalyst(s) for a particular application. In many instances, hydroprocessing is generally accomplished by contacting the selected feed stock in a reaction vessel or zone with the suitable catalyst under conditions of elevated temperature and pressure in the presence of hydrogen as a separate phase in a three-phase system (gas/liquid/solid catalyst). Such hydroprocessing is commonly undertaken in a trickle-bed reactor where the continuous phase is gaseous and not liquid.
In the trickle bed reactor, an excess of the hydrogen gas is present in the continuous gaseous phase. In many instances, a typical trickle-bed hydroprocessing reactor requires up to about 1778 nm3/m3 (10,000 SCF/B) of hydrogen at pressures up to 17.3 MPa (2500 psig) to effect the desired reactions. However, even though the trickle bed reactor has a continuous gaseous phase due to the excess hydrogen gas, it is believed that the primary reactions are taking place in the liquid-phase in contact with the catalyst, such as in the liquid filled catalyst pores. As a result, for the hydrogen gas to get to the active sites on the catalyst, the hydrogen must first diffuse from the gas phase into the liquid-phase and then through the liquid to the reaction site adjacent the catalyst.
While not intending to be limited by theory, under some hydroprocessing conditions the hydrogen supply available at the catalytic reaction site may be a rate limiting factor in the hydroprocessing conversions. For example, hydrocarbon feed stocks can include mixtures of components having greatly differing reactivities. While it may be desired, for example, to reduced the nitrogen content of a vacuum gas oil to very low levels prior to introducing it as a feed to a hydrocracking reactor, the sulfur containing compounds of the vacuum gas oil will also undergo conversion to hydrogen sulfide. Many of the sulfur containing compounds tend to react very rapidly at the operating conditions required to reduce the nitrogen content to the desired levels for hydrocracking. The rapid reaction rate of the sulfur compounds to hydrogen sulfide will tend to consume hydrogen that is available within the catalyst pore structure thus limiting the amount of hydrogen available for other desired reactions, such as denitrogenation. This phenomenon is most acute within the initial portions (i.e., about 50 to about 75 percent) of the reaction zones. Under such circumstances with the rapid reaction rate of sulfur compounds, for example, it is believed that the amount of hydrogen available at the active catalyst sites can be limited by the diffusion of the hydrogen through the feed (especially at the initial portions of the reactor). In these circumstances, if the diffusion of hydrogen through the liquid to the catalyst surface is slower than the kinetic rates of reaction, the overall reaction rate of the desired reactions (i.e., denitrogenation, for example) may be limited by the hydrogen supply and diffusion. In one effort to overcome the limitations posed by this phenomenon (hydrogen depletion), hydroprocessing catalysts can be manufactured in small shapes such as tri-lobes and quadric-lobes where the dimension of the lobe may be on the order of 1/30 inch. However, such small catalyst dimensions also can have the shortcoming of creating larger pressure drops in the reactor due to the more tightly packed catalyst beds.
Two-phase hydroprocessing (i.e., a liquid hydrocarbon stream and solid catalyst) has been proposed to convert certain hydrocarbon streams into more valuable hydrocarbon streams in some cases. For example, the reduction of sulfur in certain hydrocarbon streams may employ a two-phase reactor with pre-saturation of hydrogen rather than using a traditional three-phase system. See, e.g., Schmitz, C. et al., “Deep Desulfurization of Diesel Oil: Kinetic Studies and Process-Improvement by the Use of a Two-Phase Reactor with Pre-Saturator,” Chem. Eng. Sci., 59:2821-2829 (2004). These two-phase systems only use enough hydrogen to saturate the liquid-phase in the reactor. As a result, the reactor systems of Schmitz et al. have the shortcoming that as the reaction proceeds and hydrogen is consumed, the reaction rate decreases due to the depletion of the dissolved hydrogen. As a result, such two-phase systems as disclosed in Schmitz et al. are limited in practical application and in maximum conversion rates.
As discussed above, conventional hydroprocessing operations utilize trickle bed technology. This technology necessitates the use of large amounts of hydrogen relative to the hydrocarbon feedstock, sometimes exceeding 1685 nm3/m3 (10,000 SCF/B), and requires the use of costly recycle gas compression. The large amounts of hydrogen relative to the hydrocarbon feedstock in conventional hydroprocessing operations renders this type of operation a gas phase continuous system. U.S. Ser. No. 11/300,007 teaches that it is neither economical nor necessary to have this large excess of hydrogen to effect the desired conversion. The desired conversion can be effected with much less hydrogen, and can be economically and efficiently performed with only sufficient hydrogen to ensure a liquid phase continuous system. A liquid phase continuous system would exist at one extreme with only sufficient hydrogen to fully saturate the hydrocarbon feedstock and at the other extreme where sufficient hydrogen is added to transition to a gas phase continuous system. The amount of hydrogen that is added between these two extremes is dictated by economic considerations. Operation with a liquid phase continuous system avoids the high costs associated with a recycle gas compressor.
Other uses of liquid-phase reactors to process certain hydrocarbonaceous streams require the use of diluent/solvent streams to aid in the solubility of hydrogen in the unconverted oil feed and require limits on the amount of gaseous hydrogen in the liquid-phase reactors. For example, liquid-phase hydrotreating of a diesel fuel has been proposed, but requires a recycle of hydrotreated diesel as a diluent blended into the oil feed prior to the liquid-phase reactor. In another example, liquid-phase hydrocracking of vacuum gas oil is proposed, but likewise requires the recycle of hydrocracked product into the feed to the liquid-phase hydrocracker as a diluent. In each system, dilution of the feed to the liquid-phase reactors is required in order to effect the desired reactions. Because hydrotreating and hydrocracking typically require large amounts of hydrogen to effect their conversions, a large hydrogen demand is still required even if these reactions are completed in liquid-phase systems. As a result, to maintain such a liquid-phase hydrotreating or hydrocracking reaction and still provide the needed levels of hydrogen, the diluent or solvent of these prior liquid-phase systems is required in order to provide a larger relative concentration of dissolved hydrogen as compared to unconverted oil to insure adequate conversions can occur in the liquid-phase hydrotreating and hydrocracking zones. As such, larger and more complex liquid-phase systems are needed to achieve the desired conversions that still require large supplies of hydrogen.
These prior systems also may permit the presence of some hydrogen gas in the liquid-phase reactors, but the systems are generally limited to about 10 percent or less hydrogen gas by total volume of the reactor. Depending on the feed compositions and operating conditions, such limits on hydrogen gas in the liquid-phase system tend to restrict the overall reaction rates and the per-pass conversion rates in such liquid-phase reactors.
Furthermore, there are distinct advantages to operating in a moving bed mode as opposed to a fixed bed mode. For example, fixed catalyst beds deactivate over time resulting in a declining level of performance. Moving beds, on the other hand, enable deactivated catalyst to be removed and fresh or regenerated catalyst to be added to the reactor to provide a continuous level of performance. Generally speaking, a moving bed operation requires less catalyst and less hydrocarbon inventory than a fixed bed operation of the same capacity, see U.S. Pat. No. 5,849,976.
Similarly, there are advantages to multiple moving bed reaction zones over a single moving bed process. Multiple reaction zone enable the liquid effluent to be mixed with additional hydrogen. Increasing the number of hydrogen mix points reduces the amount of liquid recycle. Lower liquid recycle reduces the capital and operating costs of the unit. Also, multiple reaction zone beds enable the liquid effluent from each reaction zone bed to be cooled. Increasing the number of cooling points can reduce the liquid recycle if the cooling achieved by mixing with hydrogen is not sufficient.
Although a wide variety of process flow schemes, operating conditions and catalysts have been used in commercial petroleum hydrocarbon conversion processes, there is always a demand for new methods and flow schemes that provide more useful products and improved product characteristics. In many cases, even minor variations in process flows or operating conditions can have significant effects on both quality and product selection. There generally is a need to balance economic considerations, such as capital expenditures and operational utility costs, with the desired quality of the produced products.